Schlumberger Oilfield review

Sum

mer 2011

vOlume 23 N

umber 2

Summer 2011

bit design

downhole conveyance

Source rock geochemistry

environmental Advances

Oilfield Review

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11-OR-0003

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The first patent for the rotary rock bit, issued in 1909, marked the birth of the modern drillbit industry. At that time, bits were designed with two cones of interlocking milled teeth, and drilling a few feet was considered a good run. It wasnt until the 1950s that engineers designed three-cone bits that more closely resemble those currently in use.

Today, demands on drill bits are more exacting. While fixed cutter and roller cone bits were originally designed to be run to destruction, they are now expected to not only exceed drilling performance expectations but also to end the run in pristine condition. The modern drill bit must be able to drill fast, provide good steerability for directional control and last an extended period of time downhole in even the most extreme environments.

Though bit costs typically represent less than 1% of total well construction cost, the right bit can improve drilling performance immensely and in so doing deliver millions of dollars in operator savings. Indeed, the advent of polycrys-talline diamond compact (PDC) bits in the early 1970s, along with ongoing improvements to roller cone compo-nents, has played a major role in reducing overall well costs for our customers. These refinements also afford todays engineers the ability to plan the complex well tra-jectories that are critical to oil company profitability in increasingly complex reservoirs.

At first glance, it can be difficult to see the differences between a premium engineered drill bit and one that would drill at half the rate of penetration or lack the steerability. Indeed, without considerable understanding of the design complexities and materials engineering involved, it is diffi-cult to appreciate the amount of technology incorporated into modern drill bits or the scientific approach applied to current bit design and selection methods.

Today, vast improvements in materials engineering, design software and manufacturing processes deliver drill bits that are custom designed for every application. These designs are quickly validated in the virtual world of com-puter modeling and sent to production in a matter of days. This is in stark contrast to the trial-and-error approach used by early bit manufacturers. This new methodology allows the right solution to be delivered with the first design iteration, making it possible for our customers to capture savings immediately instead of after costly and time-consuming field trials.

As someone who has been involved in the drillbit indus-try for 15 years, I am delighted that this edition of Oilfield Review features an article explaining just a few of the drillbit technologies currently used by the industry (see Bit DesignTop to Bottom, page 4).

From Bit to Rig Floor: An Integrated Systems Approach to the BHA

1

But whats next? Drillbit design and improvements to diamond materials will no doubt continue to evolve. Materials engineering is what drives drillbit advancement, and we are rapidly escalating investment in that discipline. Future PDC bits will be able to drill harder rock than has been possible in the past, and the one-bit-per-interval goal will be achieved more frequently.

The long-term goal, however, is considerably more ambi-tious than drillbit evolution. Our aim is to engineer the entire bottomhole assembly as a single system rather than as discrete components. While the speed of rock destruction will always be of significant importance to drillers, overall system reliability and optimal well placement are equally important facets of truly efficient drilling operations.

Therefore, we believe the next step change in drilling performance will come via an integrated systems approach to the engineering and design of the complete BHA, includ-ing the drill bit, drilling tools and drilling fluid, as well as the directional drilling, measurement-while-drilling and logging-while-drilling toolseverything from the bit to the rig floor. The broader range of products and services now within our portfolio will enable the product development that is necessary to achieve this performance and reliabil-ity improvement.

Greater understanding of the technical issues and mitigating risks in advance of a drilling program will help our customers realize major cost savings and performance improvement. To be able to deliver these cost savings, we are significantly increasing our investment in both short- and long-term R&D projects. And we are employing unique approaches to problem solving that will attract the next generation of engineers and materials scientists to the E&P industry.

The industry will always strive for continuous improve-ment. As a service provider to oil and gas operators around the world, Schlumberger undertakes this challenge with responsibility and passion.

Guy ArringtonPresidentBits and Advanced TechnologiesSchlumberger

Guy Arrington, who since 2010 has been President, Bits and Advanced Technologies, a Schlumberger company, has been in the drilling industry for 24 years. He spent 14 years in the drillbit business, working in manufacturing, field engineering and business development in the US and internationally, and later in product and field engineering management. He joined the Schlumberger Drilling and Measurements segment in 2001, first as business development manager and later as vice president for Europe, Central Asia and Africa. Guy was vice president of deepwater operations before managing the Smith Bits and Advanced Technologies integration team during the Schlumberger-Smith merger. He has BS degrees in industrial engineering and mechanical engineer-ing from Texas A&M University.

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www.slb.com/oilfieldreview

Schlumberger

Oilfield Review1 From Bit to Rig Floor: An Integrated Systems Approach to the BHA

Editorial contributed by Guy Arrington, President, Bits and Advanced Technologies, Schlumberger

4 Bit DesignTop to Bottom

The right bit plays a key role in optimizing ROP, minimizing rigcosts and shortening the time between project commissioningand first production. At one time, engineers designed bitsbased on little more than rough estimates of the characteris-tics of the rock to be drilled. Today, however, the emergence ofhigh-speed computers has made it possible for bit designers toconsider the bit and the entire drilling system in far moredetail and in a far more holistic manner than ever before.

18 ConveyanceDown and Out in the Oil Field

Evaluating, perforating and performing mechanical services on horizontal and high-angle wells present challenges for operators and service companies. This article reviews some of the methods used to convey equipment and logging toolsdownhole for cased hole and openhole operations; the articlealso describes conveyance options for logging in high-angle and horizontal wells.

Executive EditorLisa Stewart

Senior EditorsMatt VarhaugRick von Flatern

EditorsVladislav GlyanchenkoTony Smithson

Contributing EditorsGinger OppenheimerRana RottenbergMark Andersen

Design/ProductionHerring DesignMike Messinger

IllustrationChris LockwoodTom McNeffMike MessingerGeorge Stewart

PrintingRR Donnelley-Wetmore PlantCurtis Weeks

Oilfield Review is published quarterly andprinted in the USA.

Visit www.slb.com/oilfieldreview forelectronic copies of articles in multiplelanguages.

2011 Schlumberger. All rights reserved.Reproductions without permission are strictly prohibited.

For a comprehensive dictionary of oilfieldterms, see the Schlumberger OilfieldGlossary at www.glossary.oilfield.slb.com.

About Oilfield ReviewOilfield Review, a Schlumberger journal,communicates technical advances infinding and producing hydrocarbons to employees, clients and other oilfieldprofessionals. Contributors to articlesinclude industry professionals and expertsfrom around the world; those listed withonly geographic location are employeesof Schlumberger or its affiliates.

On the cover:

A laboratory technician at Smith Bits, aSchlumberger company, performs a testto quantify bit cutter forces and cuttingsas a function of rock failure mechanismsand rock removal rates. These data areused for bit design analysis. Virtual sce-narios are run to determine parameterssuch as the optimal bit profile, blade andcutter count, gauge length, bottomholebit pattern and force balance on tricone(inset, left) and PDC (inset, right) bits.

2

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Summer 2011Volume 23Number 2

ISSN 0923-1730

53 Contributors

56 New Books and Coming in Oilfield Review

59 Defining Exploration:The Search for Oil and Gas

The second in a series of articles introducing basic concepts of the E&P industry

3

32 Basic Petroleum Geochemistry forSource Rock Evaluation

The pursuit of prospects in increasingly complex plays is giv-ing E&P companies a renewed appreciation for one of thefundamental principles of exploration: The viability of anyprospective reservoir depends on an effective source rock.Petroleum geochemistry is proving its value in helping oper-ators evaluate source rocks and quantify the elements andprocesses that control the generation of oil and gas.Geochemistry is also an important tool for reducing uncer-tainty inherent in exploration and production of frontierbasins. This article explores basic geochemical techniquesused to evaluate new prospects.

44 Technology for Environmental Advances

In recent years, the E&P industry has improved many tech-nologies and practices to remove or mitigate detrimentaleffects on the environment. These improvements have beenintroduced throughout the life cycle of fields. Many of thosenew technologies also demonstrate improved performanceover technologies they replaced.

Dilip M. KaleONGC Energy CentreDelhi, India

Roland HampWoodside Energy Ltd.Perth, Australia

George KingApache CorporationHouston, Texas, USA

Richard WoodhouseIndependent consultantSurrey, England

Alexander ZazovskyChevronHouston, Texas

Advisory Panel

Editorial correspondenceOilfield Review5599 San FelipeHouston, Texas 77056 USA(1) 713-513-1194Fax: (1) 713-513-2057E-mail: editorOilfieldReview@slb.com

SubscriptionsClient subscriptions can be obtainedthrough any Schlumberger sales office.Clients can obtain additional subscrip-tion information and update subscriptionaddresses at www.slb.com/oilfieldreview.Paid subscriptions are available fromOilfield Review ServicesPear Tree Cottage, Kelsall RoadAshton Hayes, Chester CH3 8BH UKFax: (44) 1829 759163E-mail: subscriptions@oilfieldreview.comCurrent subscription rates are availableat www.oilfieldreview.com.

Distribution inquiriesTony SmithsonOilfield Review12149 Lakeview Manor Dr.Northport, Alabama 35475 USA(1) 832-886-5217Fax: (1) 281-285-0065E-mail: DistributionOR@slb.com

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4 Oilfield Review

Bit DesignTop to Bottom

Individual bits are one of the least expensive pieces of hardware used in drilling

operations, yet the return on millions of investment dollars often depends as much

on bit performance as on any other single component of todays complex drilling

systems. Spurred by that reality, engineers today are bringing powerful, high-speed

computers and the latest in modeling and simulation

software to the science of bit design.

Prabhakaran CentalaVennela ChallaBala DurairajanRichard MeehanLuis PaezUyen PartinSteven SegalSean WuHouston, Texas, USA

Ian GarrettBrian TeggartTullow Oil plcLondon, England

Nick TetleyLondon, England

Oilfield Review Summer 2011: 23, no. 2. Copyright 2011 Schlumberger.For help in preparation of this article, thanks to Guy Arrington, Ashley Crenshaw, Diane Jordan and Chuck Muren, Houston; and Emma Jane Bloor, Sugar Land, Texas.DBOS, IDEAS, i-DRILL, ONYX and Spear are marks of Schlumberger.

Bit choice has long been viewed as a key to suc-cessful drilling operations. The right bit plays a leading role in optimizing rate of penetration (ROP), which helps minimize rig costs and short-ens the time between project commissioning and first production. In field development programs, predictable ROP is critical to efficient allocation of rigs, personnel and materiel. Operators are drilling increasingly complex, extended-reach wells in which a bit poorly matched to the forma-tion, drilling parameters, BHA or downhole tools may introduce unwanted dynamics or create forces that cause the well path to stray from the planned trajectory.

On the other hand, a correctly designed bit delivers a more in-gauge hole and a less tortuous

well path. These wellbore characteristics allow engineers to more easily log the hole and then to install the tubulars, tools and instrumentation required for the planned completion.

At one time, engineers designed and selected bits based on little more than rough estimates of formation hardness, interval depth and hydrau-lics. However, as with many aspects of drilling and production, in recent years, the science of bit design has evolved at an accelerated pace. Options within the general categories of fixed cut-ter and roller cone bits have grown from a select few to a wide variety differentiated by manufac-turing material, processes and function.1

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Summer 2011 5

While bits have never been designed in total isolation, todays high-speed computers have made it possible to consider the entire drilling system in far more detail and in a far more holis-tic manner than ever before. Designers are also able to better match the bit to the formation and thus avoid low ROP or excessive nonproductive time (NPT) caused by trips to replace worn bits.

The most damaging result of poor bit design is the creation of excessive downhole shocks and vibrations. Vibrations can cause anything from slow ROPinduced by premature bit wearto damage and ultimate failure of complex and costly downhole electronics. Vibrations are caused primarily by often-linked drilling phe-nomena known as bit bounce, stick-slip, bending and whirl (above).

Bit bounce most frequently occurs when drill-ing vertically through hard formations, usually with a roller cone bit, but it may also occur with a fixed cutter bit. The cutting action of tricone roller bits tends to create lobes on the bottom of the hole, which causes the bit to be axially dis-placed three, six or even nine times per bit revolution, changing the effective weight on bit (WOB) and repeatedly lifting the bit off and then

slamming it back to bottom. The resulting axial vibrations damage bit seals, cutting structures, bearings and BHA components and also reduce ROP and destroy downhole sensors.

One operator has said stick-slip accounts for about 50% of on-bottom drilling time.2 Stick-slip, a function of the rotary speed of the BHA, occurs when the bit stops turning due to friction between the bit and the formation. Once torque within the drillstring becomes greater than these friction forces, the bit releases from the wellbore wall and is spun by the unwinding of the long drill-string at very high angular velocities, causing destructive lateral movement.

Bending is caused by placing too much down-ward force on the drillstring. This can create lat-eral shocks when the drillstring is deformed enough to make contact with the wellbore.

Another operator has estimated that 40% of footage drilled worldwide is adversely affected by bit whirl.3 Whirl creates severe lateral movement at the bit and the BHA. A drilling imbalance brought on by a poorly selected bit or negative bit-BHA interaction pushes one side of the bit against the wellbore wall, creating a frictional force. When drilling a gauge hole, the bit rotates

about its center. But during whirl, the instanta-neous center of rotation becomes a cutter on the face or gauge of the bit, the same way a turning axle moves the instantaneous center of rotation of a cars tire to the road. As a consequence, the bit tries to rotate about this contact point.

Because the bits center of rotation moves as the bit rotates, one result of whirl is an overgauge hole. Motion within this hole may force the cut-ters to move backward (relative to the surface rotation), or laterally, causing the bit to travel lon-ger distances per revolution than in a gauge hole. These actions create high-impact loads on the bit and BHA. Whirl also creates a centrifugal force that pushes the bit toward the wall, increasing the frictional force, which in turn reinforces whirl.4

1. For more on bit types and manufacturing: Besson A, Burr B, Dillard S, Drake E, Ivie B, Ivie C, Smith R and Watson G: On the Cutting Edge, Oilfield Review 12, no. 3 (Autumn 2000): 3657.

2. Xianping S, Paez L, Partin U and Agnihorti M: Decoupling Stick-Slip and Whirl to Achieve Breakthrough in Drilling Performance, paper IADC/SPE 128767, presented at the IADC/SPE Drilling Conference and Exhibition, New Orleans, February 24, 2010.

3. Xianping et al, reference 2.4. Brett JF, Warren TM and Behr SM: Bit WhirlA New

Theory of PDC Bit Failure, SPE Drilling Engineering 5, no. 4 (December 1990): 275281.

> Vibration sources. Axial motion, or bit bounce, has a characteristic frequency whose value is a function primarily of the type of bit, mass of the BHA, drillstring stiffness and formation hardness. Torsional oscillations, or stick-slip, result from an excessive amount of torque in the drillstring. This type of motion also has a frequency dependent on the mass of the BHA, torsional stiffness of the drillstring and dogleg contact points. Stick-slip often results in transients of extreme lateral vibrations. Lateral shock refers to sideways bending of the BHA, and is often chaotically coupled to axial and torsional motions. BHA whirl is the bending and precession of the drillstring center around the borehole. This eccentered movement can be either forwardthat is, in the same rotational direction as the pipeor backward. Forward whirl is very common and is induced by centrifugal forces caused by any slight imbalance in the drill collars. Backward whirl results when the frictional forces between the drill collar and the borehole are sufficient to cause the drillstring to move backward along the borehole wall.

Bit bounce Stick-slip Bending Whirl

Axial motion

Fast

Slow

Backward

Forward

Torsional oscillations Lateral shock Eccentered drillstring

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6 Oilfield Review

Traditionally, the driller must change WOB or pipe rotation speed to counter drilling dysfunc-tions such as bit bounce, stick-slip, whirl and bending. Increasing WOB may induce stick-slip and raising the rotation speed may invite whirl. Restraining both may reduce all four types of vibrations but result in unacceptably low ROP.

The third choice is to find an optimized combi-nation of the two variables, which may be done only when the bit, BHA, drillstring and hydraulics pro-gram are integrated as part of a drilling system rather than as isolated components. Engineers have long known how to model the complete system. However, the volume of calculations to do so has historically required an investment of time that made the task economically untenable. Additionally, the parameters calculated were valid for only a sin-gle instance in a specific formation in a well.

These limitations have been overcome in recent years by the proliferation of fast, powerful computers that have allowed designers to model the performance of drilling systems for specific

applications. The result has been an increased ability to minimize axial and lateral vibrations by determining the optimum range of WOB and rpm. Even more important, engineers are able to design systems before they are manufactured.

This article looks at the tools available for modern bit design including simulation, model-ing and finite element analysis programs. Case studies from offshore West Africa, Peru and the US will demonstrate the impact increased com-puter power is having on drilling operations.

Drillstring Design as an Iterative ProcessThe aim of drillbit design is creation of a bit, which, when matched to the correct BHA, down-hole tool, formation to be drilled and drilling parameters, will perform optimally as defined by the following:ROPdurabilitystabilitysteerabilityversatility.

Each of these metrics is weighted by the oper-ator according to the specifics of the section to be drilled. For example, if fast ROP is the primary driver in a given interval, it may require sacrific-ing bit durability for faster drilling, resulting in faster bit wear. Similarly, if steerability is of pri-mary concern, the operator may be forced to use a less aggressive bit and slow the ROP.

Guided by operator objectives and the charac-teristics of the formations to be drilled, bit designers consider many options for each facet of the bit. The bit designer must first choose between a roller cone or fixed cutter bit (above).

On roller cone bits, the cones turn indepen-dently as the BHA rotates on bottom. Each cone has cutting structures of hard-faced steel or tungsten-carbide inserts. By design, they wedge and crush like chisels, or gouge and tear like shovels, depending on formation hardness.

> Drillbit designs. Selection begins with a choice between a bit whose cutting mechanism is fixed to the bit body or on roller cones. A selection of fixed cutters (left) may be further refined, based on formation hardness, by opting for PDC or natural diamonds, which are on cutter blades or impregnated into the bit body. Roller cones (right) consist of milled-tooth cutting structures or inserts.

Fixed cutter

Fixed cutter Roller cone

Roller cone

Drill bits

Polycrystalline diamondcompact (PDC)

PDC Milled tooth InsertNatural diamond Impregnated diamond

Diamond

Natural diamond Impregnated diamond

Milled tooth Insert

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Summer 2011 7

By contrast, fixed cutter bits, or drag bits, have integral blades that turn together. Their steel cutting structures may include natural dia-monds suspended in the blade matrix. The body of the fixed cutter bit is a cast of tungsten-car-bide matrix or machined steel. Composed of man-made polycrystalline diamond compact (PDC), fixed cutters shear the bottom of the hole.5

Historically, bits and BHAs were chosen through a process of elimination. For a given drilling program, engineers first chose a bit based on offset well data. The amount and value of the data vary according to location, but of special interest to drillers are bit records that include bit type and design used, ROP, footage drilled per bit and an accurate International Association of Drilling Contractors (IADC) bit grading. Based on this information, a specific bit type is chosen and run. When the driller decides the bit is no longer effectivefor example when the ROP slows below a predetermined ratethe drill-string is pulled and the bit inspected. This empir-ical bit selection process continues in many drilling programs today.

The bit is then analyzed for cutting structure wear and breakage. Historically, drillers learned through experience how to examine a used bit, called a dull, to determine what type of bit to run next or what changes to make to the bit type. In the 1950s, the industry established general guidelines for relating typical bit wear patterns to possible causes.6 In 1961, responding to a need for a common vocabulary and standard reporting method, the American Association of Oilwell Drilling Contractors (AAODC) established the first dull-bit grading system. It graded teeth and bearing wear on a 1 to 4 scale in which a 4 was a missing or totally flat tooth or a missing or locked bearing. Soon after, the system was expanded to a 0 to 8 scale with added detail.7

In March 1985, the IADC, successor to the AAODC, recognized that the system was again in need of updating. Bits had evolved since the last system update, most significantly with the inclu-sion of journal bearings and tungsten-carbide inserts.8 The new system was adopted in March 1986. In addition, a fixed cutter dull grading sys-tem, created in 1987, was revised in 1991 and was presented to the industry in 1992 (above right).9

With this standardization of wear analysis and reporting, it became possible to create bit records that could be used to select bits and drill-string components for similar wells. Smith Bits, a Schlumberger company, initiated a Drilling Record System (DRS) in 1985. Today this data-base of nearly three million drillbit runs includes records from every oil and gas field in the world.

However, as exhaustive as these records are, they contain an element of subjectivity, which can impact bit life and performance from one well to the next. Additionally, bit performance may be impacted by significant lithology variation within a field.

In past efforts to improve drilling perfor-mance, engineers have used the dull grading chart to make changes to the bit design, the BHA and drilling parameters after each run. As each new configuration was run, engineers analyzed bit performance, graded the bit and made changes

> Grading dulls. Using a linear scale from 0 to 8, engineers assign a value to cutters in the inner and outer rows of bits to indicate amount of wear. Grading numbers increase with amount of wear, with 0 representing no wear. Eight indicates that no usable cutter remains. PDC cutter wear is also measured in a linear scale from 0 to 8 across the diamond tablethe diamond section atop the cutting structureregardless of the cutter shape, size, type or exposure. Today, the dull grading system adopted by IADC includes codes to dull grade both fixed cutter (left) and roller cone (right) bits. The engineer assessing bit damage uses a chart that includes eight drillbit factors. The first four items on this chart (top) describe the cutting structure. The third and seventh spaces are for noting dull characteristics of the bit, which are the most prominent physical changes relative to its condition when manufactured. The fourth space, location, indicates the location of the primary dull characteristics noted in the third space. For fixed cutter bits, one or more of four profile codes is used to indicate the location of the noted dull characteristic. The fifth item, labeled B, refers to bearing seals and does not apply to fixed cutter bits. This space is always marked with an X when fixed cutter bits are graded. The sixth item, G, refers to gauge measurement. The gauge space is used to record the condition of the bit gauge. If the bit is still in gauge, the letter I is placed here. Otherwise, the amount by which the bit is undergauge is recorded to the nearest one-sixteenth inch. The last two spaces, remarks, are used to indicate other dull characteristics and the reason the bit was pulled.

Inner rows Outer rows Location Bearing seals Gauge 116 in.

Cutting structure B G Remarks

Reason pulledDull characteristic Other characteristic

Roller Cone Bits

IADC Bit Dull Grading Code

Fixed Cutter Bits

0

01

2 3

Inner rows Outer rows

4

5

6

7

Cone 1

Cone 2

Cone 3

Inner cutting structure(all inner rows)

Outer cuttingstructure

(gauge row only)

1 2 3 4 5 6 7 8

5. Besson et al, reference 1.6. Bentson HG and Smith HC: Rock-Bit Design, Selection

and Evaluation, paper API 56-288, presented at the Spring Meeting of the API Pacific Coast District, Division of Production, Los Angeles, May 1956.

7. Hampton SD, Garris S and Winters WJ: Application of the 1987 Roller Bit Dull Grading System, paper SPE/IADC 16146, presented at SPE/IADC Drilling Conference, New Orleans, March 1518, 1987.

8. Hampton et al, reference 7.

9. Brandon BD, Cerkovnik J, Koskie E, Bayoud BB, Colston F, Clayton RI, Anderson ME, Hollister KT, Senger J and Niemi R: First Revision to the IADC Fixed Cutter Dull Grading System, paper IADC/SPE 23939, presented at the IADC/SPE Drilling Conference, New Orleans, February 1821, 1992.

Brandon BD, Cerkovnik J, Koskie E, Bayoud BB, Colston F, Clayton RI, Anderson ME, Hollister KT, Senger J and Niemi R: Development of a New IADC Fixed Cutter Drill Bit Classification System, paper IADC/SPE 23940, presented at the IADC/SPE Drilling Conference, New Orleans, February 1821, 1992.

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8 Oilfield Review

to the system accordingly before drilling the next section or next well. The process was repeated in successive attempts to incrementally improve ROP or bit life.

In some cases, these changes resulted in little progress from one well to the next, and the driller had to restart the process. More commonly, the iterative method enjoyed at least partial success as ROP was increased or the bit was able to drill more footage before it had to be replaced. Still, well histories abound in which little improve-ment was seen even after many iterations, or, if the iterative process was successful, it was only after many such trial-and-error cycles. An itera-tive approach is particularly handicapped when the first well includes little offset data or the drilling program includes only a few wells.

The iterative process for developing optimal bit and BHA configurations is also hampered by several factors inherent in the process. Engineers of differing experience draw different conclu-sions from essentially the same wear patterns; some engineers, for example, may arrive at the cause of a particular wear pattern after making false assumptions. The most common of these assumptions is that drillstring weight is effi-ciently transferred to the bit. WOB directly

impacts ROP. An engineer may assume that poor bit selection is hampering ROP when in fact WOB, which is a function of BHA design, is actu-ally less than calculated.10 Conversely, when WOB is too high, the drillstring and BHA may bend, leading to an overgauge hole and destructive lat-eral vibrations as the angled bit engages and cuts away the borehole wall.

In 1987, efforts were made to correct this pos-sible pitfall with the introduction of BHAP, a BHA performance prediction computer program. BHA design decisions include the type, placement, shape and size of all components above the bit. Before the introduction of BHAP, engineers relied on mathematical models that used descrip-tions of the BHA components to predict WOB. These models were two-dimensional, used a con-stant wellbore curvature and were static.11

Although designed to be simple to minimize computer run time, BHAP was an improvement over previous practices that tended to view bit performance in isolation. More complex model-ing awaited the arrival of computing power that could, at reasonable speed and cost, handle mas-sive volumes of data and calculations.

An Elemental AnswerWhen BHAP was introduced, engineers had at their disposal a powerful tool for creating a more comprehensive and more accurate description of the drillstring. In the 1940s, scientists and math-ematicians seeking to analyze vibrations in com-plex machinery had introduced the world to finite element analysis (FEA). FEA involves 2D or 3D modeling and uses a complex system of nodes to create a grid called an FEA mesh. This FEA mesh is populated with the material and structural properties that define how the system will react to loading conditions. Throughout the material, the density of the nodes depends on the anticipated stress levels of a particular area. To concentrate computer power where it is needed, regions receiving large amounts of stress usually have a higher node density than those experiencing little or no stress. From each node, a mesh element extends to each of the adjacent nodes (above).12

By the 1970s, FEA was commonly used by mechanical engineers, although its application remained limited to a few users who could afford the necessary computing power. As a conse-quence, most drilling optimization computations

> FEA mesh. An FEA mesh represents a modeled bodyin this case a drillstringwith mesh elements that connect at the nodes (black lines) to critical components affecting drilling performance. This mesh is used in the IDEAS program to optimize bit cutting structures (black cylinders). In this instance, red and green patches indicate that side forces on the bit during this simulation are being imposed on the gauge of one blade (red), more so than on the other five (green).

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Summer 2011 9

relied predominantly on offset well data rather than FEA techniques to plan wells. These pro-grams attempts to assess and predict drillstring and bit behavior were restricted to static or steady-state analysis designed to understand a specific part of the system at a particular moment. These assessments were most useful as postmortem descriptions of drilling system failures and identi-fied only a fraction of the problem.13

To optimize bit and drillstring component selection and placement, engineers needed to understand the dynamic interaction of all com-ponents as drilling progressed. This finally became feasible when high-powered, fast com-puters became widely available in the 1990s. Engineers began, relatively quickly and at rea-sonable cost, to digitally recreate and analyze drilling systems and their behavior over time. Rather than performing expensive, time-con-suming field trials, engineersnow armed with dynamic modeling capabilitiesbegan to pin-point the cause of drilling system failure and then test solutions using a virtual prototype.

Dynamic models may be run to analyze the behavior of individual components, such as the bit or BHA, or they may address the entire system. The net forces and moments acting on a bit are obtained from vector sums of the contributions of individual cutters. Fixed cutter bit forces are obtained from laboratory test data; roller cone insert forces are based on simple crushing and shearing models. The equations of motion are inte-grated using a variable-timestep procedure.14 Six degrees of freedom (DOF) are allowed for the bit body: three translations and three rotations. For roller cone bits, DOF functions may be toggled off to simulate a seized cone.15 Dynamic Modeling

Engineers first applied dynamic modeling to drilling operations to improve efficiency and pro-tect expensive downhole components from destructive toolstring vibrations. This method included planning, real-time monitoring and detailed postjob analysis.

During planning, engineers identify likely dynamic dysfunctions that cause bit bounce, stick-slip and bit- and BHA-whirl. Mathematical models are then used to design BHAs based on directional control and desired ROP and to coun-ter expected dysfunctions. Downhole and surface sensors monitor dysfunction-related vibrations. Based on measurements from the sensors, model results and prior experience drilling in the field, engineers adjust drilling parameters to optimize ROP and minimize destructive vibrations.16

Usually, bit dynamic stability is ascertained through laboratory tests that determine the ROP or WOB that will force the bit to become unstable

at a given rotary speed. Bit-dynamics modeling allows the manufacturer to eliminate poor designs before bits are built and to determine optimal rotary speed ranges for a given design and downhole environment.

Drillstring-dynamics simulations are based on finite element methods. Like bit-dynamics models, each node of the BHA model has six DOF and the equations of motion are integrated using a variable-timestep procedure. When drillstring and bit-dynamics models are coupled, dysfunc-tions that hinder drilling performance can be predicted and avoided.

In the 1990s, Smith scientists introduced a comprehensive FEA program aimed at accurately modeling the total drilling system. The IDEAS integrated dynamic engineering analysis system predicts drillbit performance as part of a total drilling system (above). Based on laboratory-derived drilling mechanics and physical input

10. Williamson JS and Lubinski A: Predicting Bottomhole Assembly Performance, paper IADC/SPE 14764, presented at the IADC/SPE Drilling Conference, Dallas, February 1012, 1986.

11. Williamson and Lubinski, reference 10.12. Introduction to Finite Element Analysis, http://www.

sv.vt.edu/classes/MSE2094_NoteBook/97ClassProj/num/widas/history.html (accessed February 8, 2011).

13. Frenzel MP: Dynamic Simulations Provide Development Drilling Improvements, paper OTC 19066, presented at the Offshore Technology Conference, Houston, April 30May 3, 2007.

14. Algorithms using a variable-timestep procedure continuously monitor the accuracy of the solution during the course of the computation, and adaptively change the timestep size to maintain a consistent level of accuracy. The step size may change many times during the course of the computations; larger time steps are used when the solution is varying slowly, and smaller steps are used when the solution varies rapidly.

15. Dykstra MW, Neubert M, Hanson JM and Meiners MJ: Improving Drilling Performance by Applying Advanced Dynamics Models, paper SPE/IADC 67697, presented at the SPE/IADC Drilling Conference, Amsterdam, February 27March 1, 2001.

16. Dykstra et al, reference 15.

> Cutter design. Bit design engineers begin with an initial cutting structure layout (black cylinders) modeled within the IDEAS program. Each cutter on each blade is analyzed using force vectors (green and red lines) representing components of the cutting force. Vector length represents relative force magnitude. Color represents depth of cut according to the scale. Engineers use this information to position each cutting structure in terms of height above the blade surface, its radius from the bit center, the back rake and side rake angles, the size of the cutter and its profile angle. Back rake is the angle of cutter face in reference to bottomhole, and side rake refers to its angle relative to the radius of the bit face.

Low

Depth of cut

High

41615schD4R1.indd 9 8/12/11 7:53 PM

10 Oilfield Review

data, it uses equipment that accurately charac-terizes the cutting structures interactive mechanics during crushing and shearing across a broad range of rock samples.

These input data, captured from a series of indentation and scrape tests, are acquired under laboratory-controlled pressures to replicate the dynamic interaction between a bit cutting struc-ture and a specific rock sample (above). The experiments quantify actual cutter forces and cuttings generated in terms of magnitude and orientation as a function of both rock failure mechanisms and rock removal rates. These data are then used for the design analysis in litholo-gies comparable to the specific field application. In some cases, these tests are conducted on actual core samples from offset wells near the new well. The simulation model can incorporate either roller cone or fixed cutter bits.

Also in the early 1990s, Smith developed the DBOS drillbit optimization system, which allows engineers to characterize each target interval in terms of the unconfined compressive strength (UCS) of the rock, an abrasive index and an index of the rocks impact on cutters. Based on this assessment, the system then defines the appro-priate bit type and features with which to drill each interval of depth change. Over the years, Smith has built a database of DBOS studies, which includes bit types and formations drilled. The DBOS formation characterization database, coupled with the IDEAS simulations, enables engineers to select the appropriate rock test files for a given application.

The rock and cutter mechanics data from the IDEAS laboratory are imported into a virtual drilling environment along with information

about the specific drill bit to be evaluated. This assessment includes the following elements:precise location, material properties and

dimensions of cutters bottomhole component dimensional data and

the physical characteristics of each BHA elementgeometryoftheproposedwellboreplannedoperatingparameters.17

Bit performance can then be examined in a confined environment during initial design devel-opment. The process also predicts bit performance while considering the BHA, well geometry, drilling parameters and lithology variations. All of this is done in a dynamic simulation that considers influ-ences on the bit that are as close as possible to those it will encounter while drilling.

The resulting outputs enable designers to match projected bit performance with drilling objectives, such as ROP, footage drilled per bit and specific directional characteristics. Designers use the IDEAS software as an interactive tool to test the effects of iterative changes to bit fea-tures on overall performance in specific applica-tions. The modeling programs reveal how subtle changes in a cutters position and orientation significantly affect drilling performance and dynamic stability of the bit and BHA. The engi-neer can quickly optimize design and then use the modeling process to certify the performance capabilities of each bit through a dynamic simu-lation and modeling methodology.18

Looking for TroubleIn 2004, Smith commercialized the i-DRILL engi-neered drilling system. This engineering service uses the IDEAS program platform to quantita-tively identify the forces, vibrations and ROP for a specific complex drilling system over time. The system tests the dynamic effects of bit type, BHA design, drive mechanism and drilling parameters as a function of hole size and formation charac-teristics. This FEA drilling simulation model uses more than one million lines of code to accurately describe the total drilling system.

The simulation is created by combining a bit-rock cutting model, based on extensive labora-tory testing, with FEA of the bit and drillstring. Design engineers then evaluate the behavior of various combinations of drill bits, drillstring com-ponents and configurations, surface parameters and overbalance pressures. The dynamic behav-ior of the entire drilling system can be analyzed through multiple geological formations of varying compressive strength, dip angle, homogeneity and anisotropy to gain optimal drilling perfor-mance through formation transitions.

> Scrape and indentation tests. A roller cone insert (top) scrapes a sample rockCarthage marble herewith 3,000-psi [20.7-MPa] unconfined compressive strength (UCS) at various depths-of-cut (DOCs). In the graph (bottom) measured vertical force (red) and DOC (green) are recorded for various cutter angles. This information is then loaded into the IDEAS application as a rock file, which is specific to this rock and cutter combination.

Verti

cal f

orce

, lbf

DOC,

in.

12,000

10,000

8,000

6,000

4,000

2,000

00 60 120

Cutter angle, degree

Variation of vertical force with increases in DOC

180 240

0.18

0.20

0.14

0.16

0.10

0.12

0.06

0.08

0.04

0

0.02

41615schD4R1.indd 10 8/12/11 7:53 PM

Summer 2011 11

The i-DRILL process integrates offset well data, surface and downhole measurements and knowl-edge of available products and applications as part of the design process. It also considers detailed geo-metric input parameters and rock mechanics data. These inputs enable engineers to simulate a specific drilling operation and thus evaluate and, through dynamic analysis, correct root causes of inefficient and damaging BHA behavior. The i-DRILL system creates dynamic drilling simulations that help engi-neers visualize the downhole environment prior to drilling; this is in contrast to engineers having only static analyses, which provide just a small slice of data for a fixed point in time.

The i-DRILL modeling process begins by using the available offset well data to calibrate the simulation software for each application. The dataset may include the following:details regarding the physical characteristics

of the entire drillstring, the BHA and the drill bitdirectionalsurveysandcaliperlogstocharac-

terize the hole geometrysurface and downhole operating parameters

such as WOB, torque and rpmmudlogandwirelinelogdatatoevaluatethe

formations being drilled.

Designers use this information to build a com-puter model of the offset drilling assembly, the formations and the wellbore (above). The program simulates the operation of the drilling assembly as a function of time. Because it allows analysis of the specific target lithology and the behavior of each BHA component, any suspect behavior is identi-fied, quantified and illustrated using the systems advanced graphics capabilities. Simulation video clips accurately illustrate what would occur down-hole. The process identifies damaging and effi-ciency-reducing dysfunctions such as high rotary steerable system (RSS) contact forces, bit whirl and excessive bending moments.

Once the underlying causes of undesirable drilling characteristics are identified, the engi-neer can reconfigure the modeled drilling assem-bly and use simulation analyses to correct the problems. Corrective actions can include switch-ing to a different drill bit, exchanging stabilizers for reamers, repositioning individual BHA com-ponents, changing operating parameters or com-binations of changes that will produce significant performance improvements.

Last, the software generates a comprehensive report documenting the findings and analysis process, which designers can then present to the

operator. It contains the results of each simula-tion, identifying all potential changes that could be made to the drilling assembly and the effect that each would have on drilling performance. The operator can then select the best option to meet drilling objectives, minimize problems and improve performance.19

Dynamic modeling systems allow engineers to process a multitude of simulations represent-ing any combination of drillbit options, drilling assembly components, drillstring design, compo-nent placement and operating parameters. Because the method is highly accurate, engi-neers are able to quantitatively evaluate various scenarios and then choose a solution in which a specified performance will be achieved in the drilling operation. The method helps identify operational technical limits, which avoids NPT, and eliminates inefficiencies resulting from operating too far below the technical limits. It also helps the operator avert needless trips to change bits and BHAs that are the result of using

>Modeling milled-tooth bit operation. This view of a milled-tooth bit application generated by i-DRILL software includes displacement and contact forces at the rotary steerable system (RSS) pads (blue rectangles, top left). In this case, a cross-sectional view of the RSS oriented along the drillstring axis shows the tool to be centered in the hole. This indicates that there is no contact force on the pads, which means the wellbore trajectory is not being changed at the instant the data are captured. The pattern made by the bit on the bottom of the hole is shown (bottom left) as are critical BHAwellbore wall contact points along the BHA (red lines, right).

17. Garrett I, Teggart B and Tetley N: FEA Modeling System Delivers High-Angle Well Bore Through Hard Formations, E&P 83, no. 9 (September 2010): 6871.

18. Garrett et al, reference 17.19. Garrett et al, reference 17.

41615schD4R1.indd 11 8/12/11 7:53 PM

12 Oilfield Review

trial-and-error methods to solve particular drill-ing challenges.

Dynamic modeling was used in 2007, after Tullow Oil plc drilled successful exploration wellsMahogany-1, Mahogany-2 and Hyedua-1offshore Ghana, West Africa, which resulted in the discovery of the Jubilee field. Results from three appraisal wells drilled in 2008 confirmed that the field is a continuous stratigraphic trap.

The Jubilee field is one of only a few deepwa-ter developments in the world containing hard and abrasive formations through the reservoir sections. Engineers identified these challenging formations while drilling the first four wells in the region. With log data from the first three test wells, a rock mechanics program quantified the formations UCS between 6,000 psi and 10,000 psi [41.4 MPa and 68.9 MPa] with turbidite stringers as high as 25,000 psi [172 MPa] (above).

Due to the difficulties encountered on the first four wells, the operator commissioned a full i-DRILL study based on all the available data. This study recommended an initial seven-bladed PDC bit to drill to a planned core point. After cor-ing, a more durable nine-bladed PDC bit was rec-ommended. When the operator drilled the first appraisal wellHyedua-2the first bit wore quickly once it began to penetrate the reservoir, further confirming the abrasive nature of the res-ervoir.20 The more durable bit was run below the cored section, but after it drilled only a short dis-tance, it was pulled in response to low ROP. Once retrieved, it too was found to be badly worn. The i-DRILL process successfully predicted which bits would yield a stable system; this allowed engineers to turn their attention more specifi-cally to bit durability.

Using an FEA-based dynamic modeling sys-tem, engineers then began a series of virtual tests to identify a PDC bit optimized for the reservoir section. While engineers analyzed the results of the Hyedua-2 well and developed an improved bit and cutter design, the operator drilled three more development wells and tested several bit designs.

An optimized bit was manufactured in 2009. At the same time, Smith developed the proprie-tary, highly abrasion-resistant ONYX PDC cutter, which was incorporated into the optimized bit. On its first application in the J-02 well, it drilled the entire hard and abrasive 121/4-in. section in a single run. Further bit refinement improved per-formance. Engineers then turned their attention to the BHA design in an effort to reduce high vibration levels that were causing LWD tool fail-ure, which in turn forced the operator to run time-consuming wireline logs.

> Jubilee field well logs. Interpretations of sonic and gamma ray logs of four 121/4-in. sections of Jubilee wells drilled at different depths were used to determine lithology and UCS. The first track, lithology, includes shale (green), sandstone (red) and marl (blue). The second track shows UCS (dark blue line) with porosity (aqua shading).

3,300

psi 30,0000UCS

Depth,m

Hyedua-1 Odum-1 Mahogany-1 Mahogany-2 J-02

3,350

3,400

3,450

3,500

3,550

3,600

3,650

3,700

3,750

3,800

2,100

2,150

2,200

2,250

3,500

3,550

3,600

3,650

3,700

3,750

3,800

2,500 3,600

3,650

3,700

3,750

3,800

3,850

3,900

3,950

4,000

4,050

4,100

4,150

4,200

2,550

2,600

2,650

2,700

2,750

2,800

2,850

2,900

2,950

3,000

3,050

3,100

3,150

3,200

3,250

3,300

3,350

3,400

2,300

2,350

2,400

2,450

2,500

2,550

2,600

2,650

2,700

2,750

2,800

2,850

2,900

2,950

3,000

3,050

3,100

3,150

3,200

050 %% % % %Porosity Depth,

mDepth,m

Depth,m

Depth,m

psi 30,0000UCS

050Porosity

psi 30,0000UCS

050Porosity

psi 30,0000UCS

050Porosity

psi 30,0000UCS

050Porosity

41615schD4R1.indd 12 8/12/11 7:53 PM

Summer 2011 13

They approached the problem by studying the most recent offset well, the J-02, in a follow-up i-DRILL study with a focus on stick-slip and lat-eral vibrations. Engineers first identified condi-tions within the well that led to stick-slip and bit whirl and then replicated those conditions in a simulation. After they better understood the drill-ing dynamics of the well, engineers ran simula-tions using varying BHA, WOB and rotation speed.

From these results they recommended changes in BHA configuration and optimized operating ranges for WOB and rotation speed; they recommended the same bit, but with a motor to assist a push-the-bit RSS. This was used successfully on the next three wells, J-05, J-11 and J-12. Further bit optimization efforts focus-ing on drilling parameters allowed engineers to maintain these successes using RSS only.

These recommendations were applied to the J-05 well, which required a tangent section with a 49 inclination before reaching TD at 4,192 m [13,753 ft]. The results include an ROP improve-ment from 8.9 to 21.1 m/h [29.2 to 69.2 ft/h] and commensurate savings in rig time of about US$ 1 million/day. When retrieved, the bit, LWD tool and RSS were in good condition due to reduced vibration levels compared with those in J-02. Drilling performance from the three offset wells showed that the new PDC bit drilled 165% more footage with a 122% increase in ROP while drill-ing the reservoir interval in a single run (above).21

This system was used on the next two wells, J-11 and J-12. Further bit optimization efforts focusing on drilling parameters allowed engi-neers to maintain these successes using RSS only.

Since July 2009, with optimized BHA and parameters, the operator has used bits of the same design to drill all but one 121/4-in. section in a single run.

Special Needs Cases Some drilling scenarios are inherently more dif-ficult to optimize than others. For example, deep wells often present drillers with a particularly challenging scenario in which the initial hole

must, while it is being drilled, be enlarged, or opened, beyond the size of the bit. To accomplish this, the BHA often includes an underreamerhole opener tool located above the bit (below). Once drilling commences in a hole section to be

20. Murphy D, Tetley N, Partin U and Livingston D: Deepwater Drilling in Both Hard and Abrasive Formations; The Challenges of Bit Optimisation,

> Run details in the 121/4-in. section. Compared to the averages from offset wells (brown), the newly designed PDC bit run in J-05, J-11 and J-12 (green) drilled 165% more footage with an ROP increase of 122%. The bit was in good condition when pulled.

Well name Number Spud date Bit type Out, m Drilled, m Hours ROP, m/h Inclination, degree BHA I O C L #1

Bit Grade

#2 #3 G O R

Hyedua

Hyedua

Hyedua

Jubilee

Jubilee

Jubilee

Jubilee

02

02

02

02

05

11

12

Oct. 25, 2008

Oct. 25, 2008

Oct. 25, 2008

Apr. 11, 2009

July 22, 2009

Aug. 08, 2009

Aug. 31, 2009

TCI = tungsten carbide insert. Bit grading code: I = inner cutting structure; O = outer cutting structure; C = cone; L = location; S = shoulder; A = all areas; #1, #2, #3 = bearing; E = seals effective; X = no bearings; G = gauge; O = other dull characteristics; LT = lost cutter; NO = no dull characteristics; WT = worn cutters; RO = ring out; R = reason pulled; CP = core point; PR = penetration rate;TD = total depth, casing point.

PDC 6

PDC 4

TCI 527

PDC 5

PDC 5

PDC 5

PDC 5

3,393

3,565

3,663

4,215

4,192

4,213

4,292

996

57

98

1,135

1,702

1,481

1,349

56.0

18.5

48.5

126.6

80.5

90.5

71.1

17.8

3.1

2.0

9.0

21.1

16.4

19.0

14

Vertical

Vertical

38

49

40

44

BHA 8

Rotary

Rotary

BHA 8

BHA 12

BHA 12

BHA 12

2

1

5

3

1

2

3

8

2

4

4

2

3

8

RO

WT

BT

WT

WT

WT

WT

S

S

A

A

S

S

S

X

X

E

X

X

X

X

X

X

E

X

X

X

X

X

X

E

X

X

X

X

1

1

2

1

1

1

2

LT

NO

WT

CT

NO

NO

RO

CP

PR

TD

TD

TD

TD

TD

> Underreamerhole opener. An underreamer is designed so that its cutting structure may be expanded to a size greater than the diameter of the pilot bit once they have both exited the casing shoe and entered the interval to be opened. This concentric reamer includes a one-piece cutter block and extension mechanism design. The tongue-and-groove actuation system traverses beneath the PDC formation cutting structure blocks and opens it to a preselected diameter maintained by the simultaneously opened stabilizergauge pad. At the same time, three backreaming cutting structures are locked in place to allow the reamer to open the hole while tripping out, if required. The blocks are locked in place by the tools hydraulic system. The single-piece body design increases the tools torque and load-carrying capacity, ensuring it can efficiently handle the heavy weight of the rotary steerable system BHA.

Backreamingcutting structure

Stabilizergauge pad

Formationcutting structure

Z-drivetongue-and-groove

actuation

paper SPE 128295, presented at the SPE North Africa Technical Conference, Cairo, February 1417, 2010.

21. Murphy et al, reference 20.

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14 Oilfield Review

enlarged, engineers send a signal that expands the underreamers blades, creating a cutting tool of larger diameter than the internal diameter of the previous casing string. The object of the operation is to forestall reduction of wellbore diameter as numerous, successively smaller cas-ing strings are installed across transitional zones encountered while drilling deep wells. This strategy is also employed extensively in deepwa-ter operations in which many casing strings must be used to control drilling fluid losses as the pore-pressurefracture-gradient window quickly narrows. A larger diameter wellbore also addresses the challenge of small drilling win-dows through reduced friction pressures in the annulus, creating a lower equivalent circulating density (ECD). The intended result is a suffi-ciently large internal clearance through the pro-duction casing string to accommodate all necessary completion equipment.

Underreaming while drilling may be problem-atic in some situations. In combination with downhole motors or rotary steerable assemblies, the reamer must be strong enough to hold the added weight of the steering assembly hung below it and yet remain sufficiently pliant to deliver a quality wellbore through sometimes acute trajectory changes. Perhaps greater chal-lenges to the BHA and bit designer, however, are difficulties that arise when the reamer and bit are drilling in formations of differing hardness. This difference may cause them to drill at different

speeds, generating torsional and lateral vibra-tions in the drillstring.

In the Pagoreni field, operator Pluspetrol was experiencing vibration problems, which were resulting in unacceptably low ROP and the destruction of expensive downhole measurement tools. The Pagoreni field is located onshore in a folded Andean thrust belt in the southern portion of Perus Ucayali river basin. Pluspetrol began developing the field in May 2006. The deviated Pag1001D well reached 10,300 ft [3,139 m] MD about 1 mi [1.6 km] southeast of the surface loca-tion and confirmed the presence of commercial quantities of wet gas in the Upper Nia formation. This led the operator to launch a six-well devel-opment program aimed at recovering the fields estimated 3.5 Tcf [99.1 billion m3] of proven and probable recoverable reserves.

The vibration problems developed in the first three wells while the operator was drilling a 105/8-in. pilot hole that was opened to 121/4-in. using an expandable underreamer. In these wells, the problems were stick-slip and high axial and lateral vibrations while the tangent sections were being drilled. Trial-and-error approaches to BHA changes provided some relief from the axial and lateral vibrations but exacerbated stick-slip severity.22

The troublesome section included the follow-ing stratigraphic sequence:Vivin Formationhard, fine- to very fine-

grained, friable quartz sandstone of 11,000-psi [75.8-MPa] UCS

Chonta Superiorsoft calcareous shale andclay of 5,000-psi [34.5-MPa] UCS

Chonta Inferiorhard limestone layers of14,000-psi [96.5-MPa] UCS.

Unable to overcome the drilling dysfunctions through iterative processes, the operator requested that the i-DRILL engineering group at Smith opti-mize the BHA design, including PDC bit selection, for its fourth well, the Pag1004D. The team began by organizing offset data and information on drilling practicesfromthethreepreviousproblemwellsPag1001D, Pag1002D and Pag1003D.

These offset data were input into the BHA modeling program. The model included the PDC bit, RSS, LWD, expandable reamer and drillstring to the surface drive system. All drillstring dimen-sions and materials from offset wells, as well as a hole caliper measurement from offset wells, were incorporated into the model. The model was then calibrated using other offset data, including rota-tion speed, WOB, surface torque and hook load, as well as data from downhole measurements.

Simulations were run and adjusted repeat-edly until the offset conditions were duplicated to within a statistical match. The simulations allowed engineers to view the interaction of the previous systems and the boreholes and deter-mine the root cause for poor drilling perfor-mances in the first three wells. The resulting virtual model was then tested to predict the effects of different bit types, BHA designs, drive mechanisms and operating parameters as a func-tion of hole size and lithology.

A series of virtual cases was run to determine the optimal PDC bit profile, blade and cutter count, gauge length, bottomhole patterns and force balance on four bits. Laboratory tests helped determine the most appropriate cutting structures in terms of aggressiveness when used in combination with the 121/4-in. bit with 13-mm [0.51-in.] cutters. Smith technicians were able to make this determination using the IDEAS labora-tory to simulate the confining pressure of the spe-cific formations to be drilled. ROP potential was thencalculatedusinganFEAmodelthatconsid-ers precise dimensions and properties of the cut-ting structure, rock hardness, or UCS, lithology and confined pressure based on laboratory tests.

Engineers modeled BHA components to test various scenarios aimed at reducing vibrations. ForthePagorenifield,thei-DRILLteamidenti-fied four critical scenarios with vibration- inducing potential that could be encountered

> Four critical scenarios. Engineers identified four critical situations encountered while drilling the tangent section through the Vivin, Chonta Superior and Chonta Inferior formations with a 121/4-in. reamer and 105/8-in. pilot bit. The critical scenariosduring which damaging vibrations are most likely to occurare while the bit and reamer are in Vivin (1), the reamer is in Vivin while the bit is in Chonta Superior (2), the bit and reamer are in Chonta Superior (3) and while the reamer is in Chonta Superior and the bit is in Chonta Inferior (4).

Vivin Formation

11,000-psi UCS

ChontaSuperior Formation

5,000-psi UCS

ChontaInferior

Formation14,000-psi UCS

Reamer

Bit

1Reamer

Bit

2

Reamer

Bit

3

Reamer

Bit

4

Mea

sure

d de

pth

41615schD4R1.indd 14 8/12/11 7:53 PM

Summer 2011 15

while drilling transition zones between the Vivin, Chonta Superior and Chonta Inferior for-mations (previous page). These include the fol-lowing situations:bitandreamerinVivinreamerinVivin,bitinChontaSuperiorbitandreamerinChontaSuperiorreamerinChontaSuperior,bitinChontaInferior.

To better understand the dynamics involved in the four scenarios, engineers conducted five in-depth virtual analyses using the four candi-date bits in combination with the underreamer:weight distribution (WOB and weight onreamer)versusROP

lateralvibration(bitandreamer)versusROPtorquevibration(bitandreamer)versusROPaveragetorque(bitandreamer)versusROPriskofstick-slipversusROP.

Basedontheseanalyses,engineersconcludedthat the most critical scenario occurred when the bit was in the soft Chonta Superior Formation and the reamer in the hard Vivin Formation. That was also the section in which the reamer was least efficient. The worst case for the bit, however, occurred when the reamer was in the Chonta Superior and the bit was in the harder Chonta Inferior (above right).23Overall,theopti-malmethodtobalancetherequirementsofmaxi-mum ROP and reduced vibration through thefour challenging scenarios was to use a rotary steerablecompatiblesix-bladebitdesign.

Shale Gas Drilling Challenges Massive gas reserves are being discovered in shaleformationsaroundtheworld.Becausetheyare of extremely low permeability, these shalereservoirs are accessed using long horizontal wellbores, usually drilled with tungsten-carbide PDCbits.Theformationisthenopenedthroughmultiple hydraulic fractures.

In the Marcellus shale of the northeastern US, operators found that drilling long lateral wells withconventionalPDCbitsresultedinprematurebit failures and short runs because of bit balling, poor directional behavior and loss of toolface con-trol.Ballingwascausingpluggedbitnozzlesandpackedbitbodies(right). Cuttings were not being carried back up the annulus but instead were

accumulating around the bit, creating a potential for stuckdrillpipe.All this dramatically reducedROPandincreaseddrillstringstick-slip.

Because the Marcellus shale is a relativelynew play, engineers at Smith had to design a bit whilehaving littleoffsetdataathand.Available

history indicated numerous operators with differ-ing drillstring and BHA and bit configurations,makinganalysisdifficult.DrawingontheIDEASsystem, however, engineers at Smith offered a design that did improve ROP but did not fullyaddress toolface control and nozzle plugging.

> Transition drilling conclusions. Based on their analysis, engineers concluded that scenario 2, when the bit is in the relatively soft Chonta Superior Formation and the reamer is in the hard Vivin Formation, is the most critical of all scenarios. Scenario 2 is also the least efficient for the reamer. The worst scenario for the bit is when the reamer is in the soft Chonta Superior and the bit is in hard Chonta Inferior. Based on the resulting scores, the modeling suggested the best bit for each scenario. The study was based on a normalized results equation in which each selected drilling parameter was assigned a specific weight according to the operator importance. In this specific project, an equal weight distribution was made for average ROP, bit, reamer and surface stick-slip, bit and reamer lateral vibration and the change in downhole rotation rate.

Reamer

Bit

1Reamer

Bit

2

Reamer

Bit

3

Reamer

Bit

4

Worst scenario for bit

Worst scenario for reamer

Vivin Formation

11,000-psi UCS

ChontaSuperior Formation

5,000-psi UCS

ChontaInferior

Formation14,000-psi UCS

Mea

sure

d de

pth

>Nozzle plugging. A common problem in extended-reach shale drilling is the tendency for cuttings to collect in front of the bit face because the drillstring is idle while rig workers are making connections and the pumps are off. If the design of the body and junk slots does not allow for efficient movement of cuttings past the bit when circulation resumes after pumps are turned back on, a buildup of cuttings can occur and push into and plug the nozzles (left). Cuttings can likewise be pinched between the hole and the bit gauge, which prevents proper hole cleaning (right).

Nozzles

Junk slots

Bit faceCuttings bed

Bit face

Bit body

Cuttingstructures

Horizontal borehole wall

22. Cassanelli JP, Franco M, Perez J, Paez LC, Pinheiro C and Frenzel M: Dynamic Simulation: Solving Vibration/Stick-Slip Issues Achieves Record ROP, Pagoreni Field, Peru, presented at the Sixth International Seminar on Exploration and Exploitation of Hydrocarbons (INGEPET) Lima, Peru, October 1317, 2008.

23. Cassanelli et al, reference 22.

41615schD4R1.indd 15 8/12/11 7:53 PM

16 Oilfield Review

The initial attempt created a baseline from which engineers could design a second bit. This second iteration met steerability requirements of directional drillers and produced an acceptable ROP through the build section. This made it eas-ier, quicker and less costly to create a curve in the well path at the desired angle, azimuth and build rate.

However, ROPs through the 2,000- to 3,000-ft [610- to 914-m] lateral sections, which repre-sented the greatest portion of drilling expense, were less than satisfactory. Engineers knew that drilling with rigs typically available in North America was being slowed by poor hole cleaning due to low hydraulic energy at the bit, which is common when drilling horizontal wells in shale

formations. Design iterations that reoriented and repositioned bit nozzles did little to allevi-ate the problem.

Technicians at the Smith IDEAS laboratory could not obtain actual samples of the field rock to be drilled but were able to use DBOS analysis to match the Marcellus rocks with the Wellington and Mancos shales stored in their library. Their design aim was for good steerability through the curve to maintain good toolface control and fewer course corrections while delivering build rates of 8 to 12 per 100 ft [30 m]. They also sought a significant ROP improvement in the lat-eral sections. IDEAS tests indicated that cutting structures with flatter profiles provide lower resistance to inclination changes; these were

adopted in the design. They also settled on 0.43- to 0.51-in. [11- to 13-mm] diameter cutters because tests showed they had less depth-of-cut (DOC) compared to the larger 0.63- to 0.75-in. [16- to 19-mm] cutters. Greater DOC creates a higher instantaneous torque response, which can cause loss of toolface control and so hinder direc-tional response. Upgrades were also made to the hardfacing materials of the drill bits to better protect the steel from erosive drilling fluid.

Designers concluded that cuttings were not being carried away from the bit because the flow areas between cutter blades to the annulus, known as junk slots, were too narrow. To increase this flow area, engineers could increase the height of the bit blades while reducing their width, but that presented a problem. Current bit matrix designs are limited by the aspect ratio (blade height/blade width) because the tungsten- carbide matrix is relatively brittle and blades that exceed a certain ratio often break upon impact with the formation. Over time, the bits that were formerly made of steel had been replaced by tungsten-carbide bits, which enabled the bits to withstand the erosive forces created by abrasive formation sand and drilling fluids flowing past the bit body. As a consequence, steel PDC bits are rarely considered for use today, except to drill relatively short, low-cost sections.

A solution was found in previous practice. Because shale is characterized by low abrasive-ness, steel is sufficiently durable to drill these formations without erosion worries. And, because steel is less brittle than tungsten-carbide matrix, the blades may be extended farther from the bit body with much less potential for breakage due to impact (left). By increasing the height and decreasing the width of the blade, the flow area between the bit body and the borehole wall was dramatically increased and drill cuttings were able to pass more freely into the annulus and away from the cutting structure. Fresh rock was exposed and ROP increased.

Using steel, designers could streamline the bit body to make it easier for cuttings to sweep away from the center of the bit toward and into the junk slots. The body diameter of the bit could also be reduced, increasing the distance between the borehole and the bit body at the junk slot.

Fluid dynamics were calculated to simulate the at-bit flow regime. This allowed nozzles to be placed and oriented to minimize recirculation at the bit face, ensuring efficient cuttings removal and elimination of balling and plugging. Blade contour angles were also designed to optimize

> Bit solution for the Marcellus shale. Since bit body erosion is of less concern while drilling shales than while drilling more abrasive sands, the bit body could be made of steel. This allowed the designers to use a more streamlined body (top right) because the less brittle steel blades could be made longer and thinner without being subject to failure due to impact breakage. Steel also permits construction of a shorter bit (bottom right) than is possible with a matrix-body bit (bottom left), which enhances its ability to drill through extreme angle changes using a drilling motor.

Matrix body

Junk slots

Makeup length difference

Steel body

41615schD4R1.indd 16 8/12/11 7:53 PM

Summer 2011 17

fluid flow at, along and above the bit to minimize steel erosion from drilling mud carrying cuttings (left). The resulting hydraulics at the bit face also increased stability and reduced vibrations, which improved ROP and steerability.

This newly developed Spear steel PDC drill-bit, optimized for use in shale, has been used successfully in the Bakken, Barnett, Marcellus and Eagle Ford shale formations of North America. In the Marcellus application, the tar-get ROP goal for drilling the horizontal leg with an 83/4-in. bit was 50 ft/h [15.2 m/h]. The Spear bit achieved ROPs in excess of 65 ft/h [19.8 m/h]. In the Marcellus area, a 63/4-in. Spear bit has consistently drilled the horizontal section in one run with ROPs 10% to 20% faster than the best offset well performance.

Future PerfectionWhere once the preoccupation of the oil and gas industry was to find hydrocarbons in economic amounts, today much of its attention is focused on producing remaining and unconventional reserves. That may entail minimizing a surface footprint while drilling horizontally to reach tar-gets kilometers away and hundreds of meters beneath populated or environmentally sensitive areas. Or the challenge may simply be to drill through complex lithology with an ROP that does not destroy project economics.

Regardless of the motive, reaching many of todays potential oil and gas reservoirs requires improved drilling efficiencies to maintain eco-nomic viability. Much of what stood in the way of better drilling practices is being eroded by the revolution in gathering, organizing and imple-menting vast amounts of data quickly. The limita-tions imposed by human inability to use the immense volumes of data available from many and dissimilar sources have been largely overcome by recent quantum leaps in computing power.

FEA may be one of the most visible of these new tools for improving drilling efficiency, but there are others on the horizon. For example, while the means are in place to accumulate great amounts of data about drilling operations, opera-tors may not always know the best way to lever-age the data to improve drilling performance in future wells. One effort currently underway and now enjoying success in field trials addresses this need by using computer neural networks to learn how to best drill formations in a given field. The first step of this process is to train the neural net-work with offset data, then use a process that includes interval characterization. The system would then present the driller with real-time pre-dictions about WOB and rotation speed that would maximize bit life.

The drilling industry has long discussed auto-mated drilling. Under that general category, drill-ing operations have seen piecemeal innovations on

the rig floor in the form of iron roughnecks and automated drawworks to perform tasks once done less efficiently by hand. But a truly automated drilling system will be one able to understand and react in real time to the complex, dynamic interac-tions between bit, BHA, drillstring and the forma-tion. That may be possible soon, but will be of significantly less value if it does not begin with a properly designed bit. RvF

> Fluid flow paths. Once engineers selected the optimal Spear bit design for drilling the Marcellus shale, a computational fluid dynamics program was used to determine how the face of the cutting structure was cleaned and cooled, how effectively the hole was cleaned and how cuttings were evacuated from the bit area and passed up along the annular space. Each color represents the flow path from a specific nozzle. Modeling of fluid flow over the face of the bit (left) indicated good total coverage with no dead spots. A side perspective (right) indicated flow directed cuttings away from the bit rather than recirculating them around the bit body. A computational fluid dynamics program is used to adjust the nozzle count, size, location and orientation until an optimized design is achieved.

41615schD4R1.indd 17 8/12/11 7:53 PM

18 Oilfield Review

ConveyanceDown and Out in the Oil Field

Well productivity can be greatly enhanced by drilling high-angle wells or by

directing the wellbore into multiple targets. In such wells, traditional methods for

conveying evaluation, remediation and intervention tools are no longer practical.

In response to the challenges presented by complex well trajectories, service

companies have developed numerous innovations for accessing and evaluating

these complicated wellbores.

Matthew BillinghamRoissy-en-France, France

Ahmed M. El-Toukhy Perth, Western Australia, Australia

Mohamed K. HashemSaudi AramcoDhahran, Saudi Arabia

Mohamed HassaanDoha, Qatar

Maria LorenteTodor SheiretovSugar Land, Texas, USA

Matthew LothClamart, France

Oilfield Review Summer 2011: 23, no. 2. Copyright 2011 Schlumberger.Blue Streak, EcoScope, FMI, Litho-Density, MaxTRAC, Multi Express, SFL, TLC and TuffTRAC are marks of Schlumberger.IntelliServ is a mark of National Oilwell Varco.

You cant push a rope. Many a frustrated wireline engineer has uttered those words when logging tools failed to reach the bottom of a well, espe-cially in high-angle wells. But the source of that frustration has been overcomeat least in some respectsby the introduction of new convey-ance methods. These developments enable evalu-ation, completion and remediation not only in high-angle wells but also in long horizontal wellbores, environments that previously pre-sented insurmountable challenges to traditional logging methods.

In the days when most wells were vertical, delivering logging tools to total depth and back was a relatively straightforward task. A truck- powered winch containing a spool of cable ran the tools in and retrieved them from the well. The tools were pulled to the bottom of a well by grav-ity. The cable was also used to communicate with the tools, provide power and send information about the downhole environment back to the sur-face. This method of conveyance sufficed for openhole logging, cased hole evaluation and run-ning mechanical services, which included perfo-rating. But today, gravity is not the only means of getting tools to the bottom of the well, and cables are not the only means of delivering data to the surface; tool delivery, data transmission and equipment deployment methods abound.

This shift in techniques and methodology has developed in large part to meet the needs of wells drilled at high angles. Whereas TD once implied the deepest point in the Earth reached

by a well, the measured depth of horizontal wells often far exceeds their true vertical depth (TVD). In 2010, more than 16,000 horizontal wells were drilled worldwide.1 This number does not include thousands more wells drilled direc-tionally to reach targets far from the surface entry point or reach multiple zones separated by great lateral distances.

With todays technology, drilling engineers can create such complex wellbore geometries that delivering downhole tools to a targeted formation becomes a challenge. These wells require evaluation information when they are drilled, and they will also require some means to access the reservoir for future evaluation and intervention.2

A number of technologies have been devel-oped to address the difficulties created by com-plex wellbore trajectories. Whereas in the past, the primary consideration was simply which tools to run, today, engineers must also consider how to optimally evaluate, access and perform remedial work for the life of a well. Fortunately, the restrictive reliance on gravity to pull logging tools attached to a cable has been replaced by an expanding battery of methods, equipment and techniques. Petrophysicists and engineers now have a plethora of choices. This article reviews some of these methods and also looks at recently introduced technologies that offer greater flexibility in data acquisition choices.

1. Drilling and Production Outlook. Spears & Associates: Tulsa (June 2011): 17.

2. For more on horizontal drilling practices: Bennetzen B, Fuller J, Isevcan E, Krepp T, Meehan R, Mohammed N, Poupeau J-F and Sonowal K: Extended-Reach Wells, Oilfield Review 22, no. 3 (Autumn 2010): 415.

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Coiled Tubing

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Logging Tools on Drillpipe

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Downhole Tractor

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Logging While Drilling

Summer 2011 19

4